As the demand for natural oil and gas increases, so does the need for efficient retrieval of these limited resources from their subterranean locations. This is especially apparent in economies where the price per barrel of crude oil not infrequently fails to proportionately rise with increased demand. Hence, through an abundance of research and development, the techniques and equipment employed to remove these formation or production fluids have become increasingly sophisticated and efficient.
In atypical oil and gas recovery process, after a well has been drilled, a steel tubular casing, extending the length of the well, is inserted into the well and uncured concrete pumped down the casing. Upon forcing of the concrete out of the bottom of the casing, it fills an annular space between an outer surface of the casing and formation walls of the well, where the concrete cures to firmly anchor the casing to the well walls and seal off the well.
To access the formation fluids through the now sealed well casing, both the casing and the concrete are perforated at a predetermined downhole location below the formation fluid level (and a slurry plug in the casing). These perforations allow the production fluid to enter the well casing from the formation for retrieval. Due to the difference in pressure between the formation and the well casing interior, the inrush of the fluid into the well is substantial enough to clean the perforation passages of any debris for unobstructed passage of production fluid into the casing.
In some regions, such as in the Middle East, sufficient bottom hole pressure, via natural gas, often is available in the formation to force the production fluid to the surface, where it can be collected and utilized for commercial purposes. As the localized natural gas in these drilled formation begins to deplete, gas lifting techniques and associated apparatus are employed which inject gas into the production fluids to assist lifting of them to the surface. This gas injection typically involves inserting a smaller diameter jointed gas lift tube into the well casing. The gas lift tube includes a plurality of perforated gas lift mandrels formed for discharging gas. As the gas passes through the mandrels and into the production fluid in the annulus formed between the casing and the jointed tube, the gas mixes with and is entrained in the production fluid, causing the density, and hence the column fluid weight or gradient, to decrease. This lower weight enables the current, lower, down-hole pressure to lift the production fluids to the surface for collection.
In time, however, water seeps into or permeates the well column, which eventually impedes or prevents removal of the production fluids through gas lifting techniques. Traditionally, water is removed by purging the well with nitrogen. Purging is typically performed by inserting coil tubing into the jointed gas lift tube which coil tubing includes a one-way valve situated at the lower or distal end thereof. Nitrogen gas is discharged through the valve which exits the coil tubing at a sufficient pressure and rate to purge the undesirable water from the annulus. This purge permits the formation or production fluids to enter the annulus through the casing perforations for lifting to the surface.
While this technique has proven sufficient to remove water from the well column, the costs associated with operation can escalate. This is primarily due to the amount of nitrogen gas which must be discharged from the coil tubing, which is substantial. Other gases may be employed for purging but nitrogen is inert and available.
In some instances, a more cost-effective approach than the use of nitrogen purging can be used. A hydraulic or down-hole jet pump can be lowered into the well casing to pump water and/or production fluid from the column. Due to the small diameter tubing of some gas lift installations, however, a small diameter jet pump would be required to be inserted into the gas lift tube. Such pumps are not widely available. Larger diameter jet pumps could be deployed by removing the gas lift tubing, but this approach is impractical due to cost of removal and re-deployment of the gas lift tubing.
Hydraulic or down-hole jet pumps are often favored over mechanical-type pumps in situations such as de-watering of wells or production fluid pumping. Briefly, jet pumps generally include a power fluid line operably coupled to the entrance of the jet pump, and a return line coupled to receive fluids from a discharge end of the pump. As the pressurized power fluid is forced, by a pump at the surface, down through the down-hole jet pump, the power fluid draws in and intermixes with the production fluid. The power fluid and production fluid then are pumped to the surface through the return line, and the production fluid may then be recovered, together with the power fluid. Jet pumps are often advantageous since they generally involve substantially less moving parts than mechanical pumps, which increases their reliability. Typical of patented jet pumps are the pumps disclosed in U.S. Pat. Nos. 1,355,606; 1,758,376; 2,287,076; 2,826,994; 3,215,087; 3,887,008; 4,183,722; 4,293,283; 4,390,061; 4,603,735; and 4,790,376.
Recent developments, however, have favored the use of "free" jet pumps which enable removal of the jet pump body while retaining substantial portions of the coil tubing or jointed tubing intact in the well. The pump body can be installed for operation by pumping the body down the tubing, and it may be removed by reversing the flow of the power fluid. Hence, the "free" jet pump body may be adjusted, and/or replaced without requiring that the tubing be pulled from the well. Typical of these "free" jet pumps are the pumps disclosed in U.S. Pat. Nos. 4,658,693 and 5,083,609.
FIG. 1 illustrates a prior art high volume, "free" hydraulic jet pump 10 retrievable by reverse flow. Briefly, a coiled or jointed tubing 11 is deployed in a well casing 12 formed to slidably receive a jet pump body 13 in column 14. A bottom hole assembly 15 is mounted to a lower end of tubing 11, which is secured to well casing 12 through a packer 16 to seal casing column 14. In operation, after passage down through tubing 11, jet pump body 13 is formed to slidably seat in a vertical cavity 17 provided in bottom-hole assembly 15. A standing valve 18, situated at a lower end of jet pump 10, permits passage of production fluid therethrough into a bottom hole annulus 20 formed between the pump body and the walls forming the vertical cavity. As the pressurized power fluid in tubing 11 is forced through a jet pump nozzle 22, it intermixes with the production fluid through entrances 23 and is injected through diffuser 24 and discharged out port 25 into well casing annulus 26 for passage upwardly to the surface and retrieval.
As mentioned, these jet pumps are relatively low maintenance partially due to their lack of moving parts. One area of weakness or region of failure, however, is the O-ring or fluid seals 27, 27', 27" and 27"' carried by pump body 13 which seals cooperate with the pump body and the bottom-hole assembly housing to separate the individual intake and discharge compartments. As illustrated in the jet pump of FIG. 1, at least four O-ring seals 27, 27', 27" and 27"' are provided which form a fluid-tight seal against the interior wall 28 forming bottom-hole assembly vertical cavity 17. These fluid seals, separating the adjacent compartments, must be of sufficient integrity to withstand the high pressures generated by power fluid and the discharged production fluids.
This integrity, however, is sometimes compromised as the outward facing orientation of the fluid seals expose them to contact with the interior walls 29 of the tubing 11 as the jet pump passes therethrough. Moreover, as the jet pump seats in the vertical cavity 17 of bottom-hole assembly 15 to separate the intake and discharge compartments, the three bottommost O-ring seals 27, 27', 27" and 27"' must traverse at least one, and as many as three, other seal point 30, 30', 30" and 30"' before forming a seal with the corresponding seal wall. This sliding contact degrades the seal integrity which may cause leakage in time. This, of course, results in pump down-time, as well as, maintenance at more frequent intervals.